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The objective of the present work is to propose a methodology to predict pressure rise due to the thermal expansion of trapped liquids using computational fluid dynamics (CFD). The present study also provides a comparison between the various methods used for pressure buildup calculations that are widely used in oil and gas industries. A comparison of standard thermodynamic calculations with transient 3D CFD analysis reveals that transient CFD analyses can provide deeper insights on the temperature and velocity fields in trapped volumes. The application of the proposed method is not just restricted to a single component/equipment in the subsea field but can be applied to any trapped volume in subsea equipment. In the present study, the pressure buildup in a downhole (DH) port of a subsea Christmas tree (XT) is presented for demonstration purposes; the same methodology can be extended to other equipment or regions of interest. Because of a lack of literature on the topic of pressure rise due to thermal expansion of trapped fluids, engineers are forced to make several assumptions without knowing the effect of each term or parameter on the final pressure calculated. In this study, the percentage change/variation of the final pressure using the various forms of a standard analytical pressure rise equation is also discussed in detail.
The popular cohesive zone model (CZM) that only features decreasing cohesive traction along with crack separation might not adequately represent the fracturing behavior in organic-rich shale because of increased ductility. This paper proposes a novel CZM that can realize various traction/separation laws (TSLs) by a unified formulation to better represent the increased ductility of organic-rich shale. This modified CZM was implemented in a fully coupled in-house poroelastic extended-finite-element-method (XFEM) framework that has been comprehensively verified against the latest analytical solutions. The implications of increased ductility in different forms on hydraulic fracturing were studied using the newly designed progressive parametric study. First, the shape of the TSL affects the hydraulic fracturing given the same cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed TSL. Second, the initial tensile strength, controlling when the cohesive crack starts propagating, has the greatest effect on the hydraulic fracturing among all TSL shape parameters. The effects of TSL parameters become less significant as the fracturing-fluid viscosity increases. Finally, Young’s modulus among four common poroelastic parameters most significantly affects the brittleness of rock formation and hydraulic-fracture lengths. The increase in cohesive energy accompanied by the decrease of Young’s modulus can greatly reduce the hydraulic-fracture length under the same injection volume.
Gas adsorption, desorption, and displacement occur throughout the coalbed methane (CBM) and enhanced coalbed methane (ECBM) recovery process, causing the coal pores to deform and affecting injectivity and productivity. The primary objectives of this study include determining the pressure at which the monolayer adsorption transitions to multilayer adsorption and linking the swelling strain to both classes of adsorption. In this study, the simplified local density (SLD) theory was first modified and applied to describe the characteristics of both types of adsorption and to determine the transition pressure. A strain model coupled with the SLD theory was then developed to describe adsorption-induced deformation. Next, the measured methane (CH4) and carbon dioxide (CO2) adsorption isotherms, and strain data on the same coals, were collected for model validation. Results suggest that gas adsorbed on coal surfaces at the very beginning (monolayer adsorption) and the adsorption on other gas molecules continues once the surface has been filled (multilayer adsorption). Results also suggest that swelling strain is proportional to both types of adsorption, with the multilayer case being larger than the monolayer case. This difference may be due to the additional repulsion between the adsorbate and multilayer liquid film.
The primary objective of this study is to develop fast analytical and/or semianalytical (A/SA) solutions for the problem of liquid flow/ production and pressure interference in multifractured systems between parallel horizontal wells in ultralow-permeability reservoirs. We propose a new A/SA method that reduces the 3D flow equation into either a simple algebraic equation or an ordinary differential equation (ODE) in a multitransformed space, the inversion of which yields solutions at any point in space and time.
In the proposed transformational decomposition method (TDM), a general, fully linearized form of the 3D partial-differential equation (PDE) describing low-compressibility liquid flow through porous and fractured media is subjected first to Laplace transforms (LTs) to eliminate time, and then to successive finite cosine transforms (FCTs) that eliminate either all three dimensions, yielding a simple algebraic equation, or two dimensions, yielding an ODE in space only. Inversion of the solutions of the multitransformed space equations provides solutions that are analytical in space and semianalytical in time. The TDM completely eliminates the need for time and space discretization, thus dramatically reducing the input-data requirements and long execution times of numerical simulations.
The Fortran 95 code for the TDM solutions requires limited inputs and is easy to use. Because of the linearity requirements of the Laplace transformation of the underlying PDE, the TDM is only rigorously applicable at greater than the bubblepoint pressure. Using 3D stencils (the minimum repeatable elements in the horizontal well and hydraulically fractured system) as the basis of our study, solutions over extended production times were obtained for a range of isotropic and anisotropic matrix and fracture properties, constant and time-variable production regimes (rates or bottomhole pressures), combinations of stimulated reservoir volume (SRV) and non-SRV subdomains, variable hydraulic-fracture (HF) dimensions, and inner and boundary (toe and heel) stencils. The results were compared with analytical solutions (available for simple problems and domain geometries), as well as with numerical solutions from a widely used, fully implicit 3D simulator that involves very fine discretization of a 3D domain comprising more than 356,000 elements.
The TDM solutions were shown to be in excellent agreement with the reference analytical and/or numerical solutions, while requiring a fraction of the memory and execution times of the latter because of the elimination of the need for time and space discretization. The TDM is an entirely new approach for the analysis of low-compressibility liquid flow and pressure interference in hydraulically fractured ultralow-permeability reservoirs. The TDM solutions have the potential to provide a reliable and fast tool to identify the dominant mechanisms and factors controlling the system behavior and can act as the basis for a rapid initial parameter identification in a history-matching process for possible further refinement using full numerical modeling at less than the bubblepoint pressure.
Maraj, Priya (BP) | Huber, Ken (BP) | Itter, David (BP) | Nelson, Jeff (BP) | Rabinovich, Michael (BP) | Youngmun, Alex (BP) | Antonov, Yuriy (Baker Hughes) | Mejia, Luis (Baker Hughes) | Martakov, Sergey (Baker Hughes) | Pazos, Jhonatan (Baker Hughes) | Small, Austin (Baker Hughes) | Tropin, Nikita (Baker Hughes)
A significant oil resource exists within the Schrader Bluff and stratigraphic equivalent West Sak reservoirs located on the central North Slope of Alaska. The Schrader Bluff resource is under development in the Kuparuk River Unit, Milne Point, and within the Prudhoe Bay Unit. These areas have developed reservoirs with oil viscosities up to 200 cp under waterflood and viscosity-reducing miscible gas injection. A grass roots penta-lateral gas-lifted producer was drilled and completed to unlock untapped oil in the northern portion of the Polaris S-Pad Schrader Bluff viscous oil reservoir in Prudhoe Bay, Alaska. This producer was the first multilateral well drilled in the Orion and Polaris Schrader Bluff reservoirs in ≈8 years. The team worked to unlock surface and subsurface opportunities, delivering a substantially lower cost of access than planned. Production rate from Schrader Bluff reservoir wells has a positive correlation with contacted net sandstone. Optimal well placement in each of the five laterals was key to the delivery of a successful project. A novel approach to geosteering was used to maximize net sandstone exposure, utilizing deep azimuthal resistivity and real-time user-guided multilayered inversion modeling.
Wang, Mingyuan (University of Texas at Austin) | Argüelles-Vivas, Francisco J. (University of Texas at Austin) | Abeykoon, Gayan A. (University of Texas at Austin) | Okuno, Ryosuke (University of Texas at Austin)
The main objective of this research was to investigate the effect of initial water saturation on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for the components oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant).
Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension (IFT) between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine.
Although the two cases showed different characteristics of the mass transfer through the fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
The existing American Petroleum Institute (API) equation for internal leak predicts the internal pressure to overcome the pin-box contact pressure generated from the makeup interference plus the energizing effect of internal pressure, which enhances the seal. For threaded connections, internal and external pressures close the connection and increase the leak resistance, whereas axial loads open the connection and decrease the leak resistance. These competing effects must be included to accurately assess the connection leak resistance under any combination of loads at any point in any string. Following the same approach used by the API for internal leak, this paper obtains similar results for external leak. For API connections, the effects of combined axial force and backup pressure are then incorporated into the internal/external leak equations using results from a “toy connector” elastic model. Sensitivities of leak ratings to combined loads for API connections are presented for both tubing and casing sizes. An example design case shows the importance of considering combined loads.
Javaheri, Mohammad (Chevron) | Tran, Minh (University of Southern California) | Buell, Richard Scot (Chevron) | Gorham, Timothy (Chevron) | Munoz, Juan David (Chevron) | Sims, Jack (Chevron) | Rivas, Stephen (Chevron)
Horizontal steam injectors can improve the efficiency of thermal operations relative to vertical injectors. However, effective in-well and reservoir surveillance are needed to understand steam conformance. Uniform steam-chest development improves the steam/oil ratio in continuous steam injection and accelerates recovery in cyclic steam injection. The conformance of the injected steam can be achieved by flow control devices (FCDs) deployed on either tubing or liner. A new liner-deployed FCD was used in a horizontal steam injector in the Kern River field. The liner-deployed FCD is intended to replace the tubing-deployed FCDs while reducing capital costs, surveillance costs, and well intervention costs for conformance control.
Fiber optics was used for surveillance, which is the most promising method in horizontal steam injectors considering reliability, accuracy, and cost. Fiber optic data enables monitoring the performance of liner-deployed FCDs as well as estimating the flow profile along the lateral length. Multimode distributed temperature sensing (DTS) optical fibers and single-mode distributed acoustic sensing (DAS) optical fibers were installed in the well for these objectives. Algorithms for interpreting DTS were improved to include a new technique, shape language modeling (SLM), and a probabilistic approach. The configuration of the FCDs was changed during the first well intervention, and it was monitored by DTS and DAS. Data from both DTS and DAS confirms the open/closed position of the sliding sleeve of FCDs initially and after the intervention. The probabilistic estimates of steam outflow in several FCD configurations match well with the theoretical outflow that is expected from the critical flow of steam through chokes installed in the FCDs.
The paper presents a risk management tool that assesses the impact that potential future carbon taxes will have on a company's hydrocarbon Reserves base and associated cashflows. Based on a number of case studies, this paper will present a practical application of the open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE), developed by Stanford University. The paper will demonstrate the application of the OPGEE model in the assessment of a range of carbon taxes, how they may vary the economic limit of a field's Reserves, and how this may influence a company's future field development decisions. This tool becomes useful in the risk management of the portfolio planning and capital allocation process where carbon tax risk can be objectively assessed and tested. If utilised correctly, the model can help to future-proof a company's hydrocarbon assets in an increasingly carbon constrained world. Asset owners or potential asset acquirers can assess the materiality of potential carbon tax impositions on assets and can prepare and adjust portfolios accordingly on an informed basis.
Securing long-term energy supply for Malaysia is one of the prime responsibilities of PETRONAS; and Malaysia Petroleum Management (MPM) has been entrusted to shape the industry and enable efficient exploitation strategies and optimal development planning of Malaysian hydrocarbon assets. Production sustainability and reserve growth/addition are among the key focus area in MPM; hence, strategies and efforts are being formulated to improve the average oil field RF to more than 40%. Objective assessment of field performance, identification of recovery gaps and defining roadmap to improve field's ultimate recovery factor are critical steps to maximize the field potential ad ultimate value. This paper demonstrates the application of a hybrid workflow, comprising of data analytics-based performance benchmarking and Field Development Plan (FDP) analog assessment, to identify potential development and field management opportunities for improving economic recovery factor of an oilfield.
This novel workflow consists of three key steps. First step involves reservoir performance assessment through application of diagnostic plots, decline trends and pressure/production/injection history to validate existing reserves classified as ‘No Further Activity’ (NFA). NFA reserves along with maturity assessment of undeveloped/contingent resources will provide validated recovery factor for the field. Second step is gap analysis of validated recovery factor against benchmark RF computed through data analytics carried out in Reservoir Performance Benchmarking (RPB) tool. The third and final step focusses on monetizing the RF gap and replicating best development practices through assessment of analogue reservoirs and Field Development Plans (FDPs). Analogue development cases can be from reservoirs within same field or reservoirs with similar complexity index based on RPB tool. This step involves making various cross-plots to identify opportunities like infill drilling, secondary recovery requirement, optimal producer to injector ratio, waterflood & production optimization and operational excellence.
This workflow has been successfully applied to various oilfields (mature & greenfield) within Malaysia and results have been presented in this paper. The workflow has helped to identify numerous development opportunities to improve economic recovery factor e.g. new producer/injector wells, monetization plan for minor oil reservoirs, waterflood optimization and voidage management plans. These opportunities (subsurface/well/surface) are being matured for execution through MPM's enabling processes like Asset Value Framing (AVF), Asset Development Integrated Review (ADIR) and Asset Management Integrated Review (AMIR).
Application of recovery factor improvement workflow coupled with reservoir benchmarking results has facilitated opportunity identification in Malaysian oilfields and defined roadmap to augment nation's oil reserves base and improve the average oil field RF to more than 40%. Using this workflow, RF gap identification in existing oilfields can be completed in relatively short period of time and actionable plans can be framed for maximizing recovery factor of the respective field.